US9796490B2 - Aqueous solution and method for use thereof - Google Patents

Aqueous solution and method for use thereof Download PDF

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US9796490B2
US9796490B2 US14/062,291 US201314062291A US9796490B2 US 9796490 B2 US9796490 B2 US 9796490B2 US 201314062291 A US201314062291 A US 201314062291A US 9796490 B2 US9796490 B2 US 9796490B2
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Prior art keywords
acid
formation
treatment fluid
amino acid
wellbore
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US20150114647A1 (en
Inventor
Li Jiang
Bruno Lecerf
Murtaza Ziauddin
Richard D. Hutchins
Timothy G. J. Jones
Jian He
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Schlumberger Technology Corp
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Schlumberger Technology Corp
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Priority to US14/062,291 priority Critical patent/US9796490B2/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: LECERF, BRUNO, HUTCHINS, RICHARD D., ZIAUDDIN, MURTAZA, JONES, TIMOTHY G. J., HE, JIAN, JIANG, LI
Priority to AU2014227472A priority patent/AU2014227472B2/en
Priority to RU2014139259A priority patent/RU2686210C2/ru
Priority to EP14187120.2A priority patent/EP2883932A3/fr
Priority to BR102014024638A priority patent/BR102014024638A2/pt
Priority to CA2865855A priority patent/CA2865855C/fr
Priority to MX2016013595A priority patent/MX359204B/es
Priority to MX2014012153A priority patent/MX350752B/es
Priority to CN201410558608.6A priority patent/CN104560004B/zh
Priority to SA114350799A priority patent/SA114350799B1/ar
Priority to ARP140103989A priority patent/AR098172A1/es
Publication of US20150114647A1 publication Critical patent/US20150114647A1/en
Priority to US14/824,362 priority patent/US9920606B2/en
Priority to US15/790,928 priority patent/US20180044042A1/en
Publication of US9796490B2 publication Critical patent/US9796490B2/en
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B65—CONVEYING; PACKING; STORING; HANDLING THIN OR FILAMENTARY MATERIAL
    • B65B—MACHINES, APPARATUS OR DEVICES FOR, OR METHODS OF, PACKAGING ARTICLES OR MATERIALS; UNPACKING
    • B65B3/00—Packaging plastic material, semiliquids, liquids or mixed solids and liquids, in individual containers or receptacles, e.g. bags, sacks, boxes, cartons, cans, or jars
    • B65B3/04—Methods of, or means for, filling the material into the containers or receptacles
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids

Definitions

  • embodiments relate to compositions comprising hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio is between 0.2 and 1.5, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • inventions relate to methods for treating a formation in a subterreanean well.
  • An aqueous composition is prepared that comprises hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive, and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio is between 0.2 and 1.5, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • An oilfield treatment fluid that contains the aqueous composition is provided to a high-pressure pump. The high-pressure pump is then operated to treat at least one of a wellbore and the formation fluidly coupled to the wellbore.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • inventions relate to methods for stimulating a subterranean well having a wellbore.
  • An aqueous composition is prepared that comprises hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive, and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio is between 0.2 and 1.5, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • An oilfield treatment fluid that contains the aqueous composition is provided to a high-pressure pump. The high-pressure pump is then operated to stimulate at least one of a wellbore and the formation fluidly coupled to the wellbore, thereby increasing formation permeability.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • embodiments relate to methods for handling a composition.
  • An aqueous solution is provided that has a hydrochloric acid concentration exceeding 37 wt %.
  • An amino acid fixing agent is added to the solution, wherein the amount of fixing agent includes a molar ratio of fixing agent:hydrochloric acid between 0.2 and 1.5.
  • the solution is placed into an atmospherically pressured vessel, and the vessel is transported to a service location over a public road, a railway or both.
  • FIG. 1 depicts example equipment to treat a wellbore and/or a formation fluidly coupled to the wellbore.
  • compositions used/disclosed herein can also comprise some components other than those cited.
  • each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context.
  • a concentration range listed or described as being useful, suitable, or the like is intended that any and every concentration within the range, including the end points, is to be considered as having been stated.
  • “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10.
  • a formation includes any underground fluidly porous formation, and can include without limitation any oil, gas, condensate, mixed hydrocarbons, paraffin, kerogen, water, and/or CO 2 accepting or providing formations.
  • a formation can be fluidly coupled to a wellbore, which may be an injector well, a producer well, and/or a fluid storage well.
  • the wellbore may penetrate the formation vertically, horizontally, in a deviated orientation, or combinations of these.
  • the formation may include any geology, including at least a sandstone, limestone, dolomite, shale, tar sand, and/or unconsolidated formation.
  • the wellbore may be an individual wellbore and/or a part of a set of wellbores directionally deviated from a number of close proximity surface wellbores (e.g. off a pad or rig) or single initiating wellbore that divides into multiple wellbores below the surface.
  • a number of close proximity surface wellbores e.g. off a pad or rig
  • single initiating wellbore that divides into multiple wellbores below the surface.
  • an oilfield treatment fluid includes any fluid having utility in an oilfield type application, including a gas, oil, geothermal, or injector well.
  • an oilfield treatment fluid includes any fluid having utility in any formation or wellbore described herein.
  • an oilfield treatment fluid includes a matrix acidizing fluid, a wellbore cleanup fluid, a pickling fluid, a near wellbore damage cleanup fluid, a surfactant treatment fluid, an unviscosified fracture fluid (e.g. slick water fracture fluid), and/or any other fluid consistent with the fluids otherwise described herein.
  • An oilfield treatment fluid may include any type of additive known in the art, which are not listed herein for purposes of clarity of the present description, but which may include at least friction reducers, inhibitors, surfactants and/or wetting agents, fluid diverting agents, particulates, acid retarders (except where otherwise provided herein), organic acids, chelating agents, energizing agents (e.g. CO 2 or N 2 ), gas generating agents, solvents, emulsifying agents, flowback control agents, resins, breakers, and/or non-polysaccharide based viscosifying agents.
  • additives e.g. CO 2 or N 2
  • a high pressure pump includes a positive displacement pump that provides an oilfield relevant pumping rate—for example at least 80 L/min (0.5 bbl/min or bpm), although the specific example is not limiting.
  • a high pressure pump includes a pump capable of pumping fluids at an oilfield relevant pressure, including at least 3.5 MPa (500 psi), at least 6.9 MPa (1,000 psi), at least 13.8 MPa (2,000 psi), at least 34.5 MPa (5,000 psi), at least 68.9 MPa (10,000 psi), up to 103.4 MPa (15,000 psi), and/or at even greater pressures.
  • Pumps suitable for oilfield cementing, matrix acidizing, and/or hydraulic fracturing treatments are available as high pressure pumps, although other pumps may be utilized.
  • treatment concentration as utilized herein should be understood broadly.
  • a treatment concentration in the context of an HCl concentration is a final concentration of the fluid before the fluid is positioned in the wellbore and/or the formation for the treatment.
  • the treatment concentration may be the mix concentration available from the HCl containing fluid at the wellsite or other location where the fluid is provided from.
  • the treatment concentration may be modified by dilution before the treating and/or during the treating. Additionally, the treatment concentration may be modified by the provision of additives to the fluid.
  • Example and non-limiting treatment concentrations include 7.5%, 15%, 20%, 28%, 36%, and/or up to 45.7% HCl concentration in the fluid.
  • a treatment concentration is determined upstream of additives deliver (e.g.
  • the treatment concentration is a liquid phase or acid phase concentration of a portion of the final fluid—for example when the fluid is an energized or emulsified fluid. In certain embodiments the treatment concentration exceeds 15%. In certain embodiments, the fluid concentration exceeds 36% or exceeds 37%.
  • an amino acid fixing agent has utility in retarding the rate at which hydrochloric acid solutions react with carbonate-mineral surfaces. Such retardation is useful in the context of stimulating or improving production from subterranean formations that contain hydrocarbons, steam, geothermal brines and other valuable materials as known in the art. Slowing the rate of reaction may allow deeper penetration of the acid into the subterranean formations, thereby increasing the formation permeability and productivity.
  • compositions comprising hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio may be between 0.2 and 1.5, or 0.5 and 1.5 or 0.2 and 1.1, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • inventions relate to methods for treating a formation in a subterreanean well.
  • An aqueous composition is prepared that comprises hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive, and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio may be between 0.2 and 1.5, or 0.5 and 1.5 or 0.2 and 1.1, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • An oilfield treatment fluid that contains the aqueous composition is provided to a high-pressure pump. The high-pressure pump is then operated to treat at least one of a wellbore and the formation fluidly coupled to the wellbore.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • inventions relate to methods for stimulating a subterranean well having a wellbore.
  • An aqueous composition is prepared that comprises hydrochloric acid at a concentration between 8 wt % and 28 wt % inclusive, and at least one amino acid.
  • the amino acid/hydrochloric acid molar ratio may be between 0.2 and 1.5, or 0.5 and 1.5 or 0.2 and 1.1, and sufficient water is present to dissolve the hydrochloric acid and the amino acid.
  • An oilfield treatment fluid that contains the aqueous composition is provided to a high-pressure pump. The high-pressure pump is then operated to stimulate at least one of a wellbore and the formation fluidly coupled to the wellbore, thereby increasing formation permeability.
  • the amino acid may comprise alanine, asparagines, aspartic acid, cysteine, glutamic acid, histidine, leucine, lysine, methonine, proline, serine, threonine or valine or combinations thereof.
  • the selection of a molar ratio of amino acid:HCl depends upon the specific embodiment, and is a mechanical step for one of skill in the art having the benefit of the disclosures herein. It will be understood that an upper limit of amino acid is present as the solubility of the amino acid and HCl in the aqueous solution is reached, and that higher molecular weight FA materials will provide lower molar ratios of amino acid:HCl at the highest HCl concentrations.
  • the amino acid is selected having a molecular weight below 100 g/mol. Additionally or alternatively, the FA may have a molecular weight below 150 g/mol, below 175 g/mol, or greater than these values.
  • the composition may further comprise hydrofluoric acid (HF).
  • HF hydrofluoric acid
  • HF exhibits distinct reactions from HCl, and is useful in certain applications to enhance the activity of the resulting aqueous solution.
  • HF is utilized in the cleanup of sandstone formations where HCl alone is not effective for removing certain types of formation damage. It is believed that the present aqueous solution will complex with HF similarly to the observed effects with HCl. Accordingly, solutions can be formulated with a total acid amount that is much higher than presently attainable formulations.
  • the HF is present in an amount of at least 0.25% by weight.
  • the HF may be present in an amount of up to 2%, up to 6%, up to 10%, up to 15%, or greater amounts.
  • the HF may be present in addition to the amount of HCl, and/or as a substitution for an amount of the HCl.
  • the composition may exhibit an acid retardation factor higher than or equal to 15 at 20° C.
  • the composition may exhibit an acid retardation factor higher than or equal to 15.
  • the retardation factor indicates the ratio between the time required for retarded HCl to consume a given amount of limestone, compared to the time required for an HCl solution at an equal concentration to consume the same amount of limestone.
  • a system 100 is depicted having example equipment to treat a wellbore 106 and/or a formation 108 fluidly coupled to the wellbore 106 .
  • the formation 108 may be any type of formation.
  • the wellbore 106 is depicted as a vertical, cased and cemented wellbore 106 , having perforations providing fluid communication between the formation 108 and the interior of the wellbore 106 .
  • none of the particular features of the wellbore 106 are limiting, and the example is provided only to provide an example context 100 for a procedure.
  • the system 100 includes a high-pressure pump 104 having a source of an aqueous solution 102 .
  • the aqueous solution 102 includes an amino acid fixing agent FA and HCl, the HCl in an amount between 8% and 28% inclusive, and the FA present in a molar ratio between 0.2 and 1.5 inclusive.
  • the aqueous solution 102 further includes water in an amount sufficient to dissolve the HCl and the FA.
  • the high pressure pump 104 is fluidly coupled to the wellbore 106 , through high pressure lines 120 in the example.
  • the example system 100 includes a tubing 126 in the wellbore 106 .
  • the tubing 126 is optional and non-limiting. In certain examples, the tubing 106 may be omitted, a coiled tubing unit (not shown) may be present, and/or the high pressure pump 104 may be fluidly coupled to the casing or annulus 128 .
  • a second fluid 110 may be a diluting fluid, and the aqueous solution 102 combined with some amount of the second fluid 110 may make up the oilfield treatment fluid.
  • the diluting fluid may contain no HCl, and/or HCl at a lower concentration than the aqueous solution 102 .
  • the second fluid 110 may additionally or alternatively include any other materials to be added to the oilfield treatment fluid, including additional amounts of an FA.
  • an additional FA solution 112 is present and may be added to the aqueous solution 102 during a portion or all of the times when the aqueous solution 102 is being utilized.
  • the additional FA solution 112 may include the same or a different FA from the aqueous solution 102 , may include all of the FA for the oilfield treatment fluid, and/or may include FA at a distinct concentration from the aqueous solution.
  • the high-pressure pump 104 can treat the wellbore 106 and/or the formation 108 , for example by positioning fluid therein, by injecting the fluid into the wellbore 106 , and/or by injecting the fluid into the formation 108 .
  • Example and non-limiting operations include any oilfield treatment without limitation.
  • Potential fluid flows include flowing from the high-pressure pump 104 into the tubing 126 , into the formation 108 , and/or into the annulus 128 .
  • the fluid may be recirculated out of the well before entering the formation 108 , for example utilizing a back side pump 114 .
  • the annulus 128 is shown in fluid communication with the tubing 126 , although in certain embodiments the annulus 128 and the tubing 126 may be isolated (e.g. with a packer).
  • Another example of fluid flow includes flowing the oilfield treatment fluid into the formation at a matrix rate (e.g. a rate at which the formation is able to accept fluid flow through normal porous flow), and/or at a rate that produces a pressure exceeding a hydraulic fracturing pressure.
  • the fluid flow into the formation may be either flowed back out of the formation, and/or flushed away from the near wellbore area with a follow up fluid.
  • Fluid flowed to the formation may be flowed to a pit or containment (not shown), back into a fluid tank, prepared for treatment, and/or managed in any other manner known in the art. Acid remaining in the returning fluid may be recovered or neutralized.
  • fluid flow includes the aqueous solution 102 including HCl, with FA being optional and in certain embodiments not present in the aqueous solution 102 .
  • the example fluid flow includes a second aqueous solution 116 including FA.
  • the fluid flow includes, sequentially, a first high-pressure pump 104 and a second high-pressure pump 118 treating the formation 108 .
  • the second high-pressure pump 118 in the example is fluidly coupled to the tubing 126 through a second high pressure line 122 .
  • the fluid delivery arrangement is optional and non-limiting. In certain embodiments, a single pump may deliver both the aqueous solution 102 and the second aqueous solution 116 .
  • either the first aqueous solution 102 or the second aqueous solution 116 may be delivered first, and one or more of the solutions 102 , 116 may be delivered in multiple stages, including potentially some stages where the solutions 102 , 116 are mixed.
  • embodiments relate to methods for handling a composition.
  • An example procedure includes combining an amount of water with a fixing agent (FA), where the amount of water is present in an amount between 0.3 and 1.3 times the mass of the FA.
  • the procedure further includes dissolving an amount of HCl into the combined amount of water and FA.
  • the dissolution of the HCl gas may occur after dissolving of the FA, simultaneous with the dissolving of the FA, or at least partially before the dissolving of the FA.
  • the amount of HCl gas is in a molar ratio of between 4.0 and 0.5 times the amount of the FA.
  • the total amount of HCl gas dissolved into the aqueous solution is greater than 37% by weight.
  • the procedure includes dissolution of at least a portion of the FA in the water during the dissolution of the HCl gas in the combined water and FA.
  • Example operations include beginning the dissolution of the HCl and adding the FA as a solid or a solution, providing some of the FA in solution with the water and some of the FA as a solid, and/or providing the FA as a solid in the water and dissolving the HCl into the water while dissolving the FA.
  • Another example procedure includes providing an aqueous solution having an amount of HCl exceeding 37% by weight.
  • the procedure further includes an operation to suppress gaseous HCl fumes from the aqueous solution.
  • the operation to suppress the gaseous HCl fumes includes an operation to add an HCl fixing agent (FA) to the solution, where the amount of FA includes a molar ratio of FA:HCl of between 0.2 and 1.5 inclusive.
  • the FA includes one or more amino acids.
  • the operation to add the fixing agent may be performed before, simultaneously, and/or partially after the addition of the HCl into the solution.
  • An example procedure further includes an operation to transport the HCl solution over a public road and/or a railway.
  • the operation to transport the HCl solution includes placing the HCl solution into an atmospherically pressured vessel, and/or a standard fluid vessel which does not provide for a pressurized environment.
  • Another example procedure includes transporting the HCl solution having over 37% HCl by weight to a location, and diluting the HCl solution to a desired HCl concentration after the transporting.
  • Example dilution concentrations include, without limitation, diluting the solution to 7.5% HCl, to 15% HCl, and/or to 28% HCl by weight. Any other concentrations are also contemplated herein.
  • the transport and dilution allows for reduced transport costs and risk (e.g. fewer transport vessels) while providing the desired total amount of HCl at the usage location.
  • An example procedure further includes residing the HCl solution in an atmospheric pressure vessel for a time period, which may be a period of at least an hour.
  • the operation to reside the HCl solution in an atmospheric pressure vessel includes residing the solution without adding an additional acid retarder to the HCl solution. Any acid retarder is contemplated herein, and the exclusion of other acid retarders in certain embodiments is optional.
  • Another example procedure includes positioning an operator into a vapor space communication with the HCl solution, and performing a fluid utility operation after the positioning.
  • Example and non-limiting fluid utility operations that may put an operator into a vapor space communication with the HCl solution include checking a fluid level of the HCl solution (e.g. a visual depth check, and/or a fluid depth check with a device); performing a fluid test on the HCl solution (e.g. fluid property test, pH reading, taking a fluid sample for testing); adding an amount of an additive to the aqueous solution (e.g.
  • a fluid transfer device e.g. connecting a fluid transfer line, inserting a transfer line into the top of a vessel
  • agitating the HCl solution e.g. with a stirrer, gaseous agitation, and
  • the procedure includes any one of a number of specific embodiments.
  • An example includes treating with the first oilfield treatment fluid and then the second oilfield treatment fluid, or treating with the second oilfield treatment fluid then the first oilfield treatment fluid.
  • An example includes the first oilfield treatment fluid including no FA, including FA in an amount distinct from the amount of FA1 in the second oilfield treatment fluid, and/or including FA1 in an amount that is the same or similar to the amount of FA1 in the second oilfield treatment fluid.
  • An example includes the second oilfield treatment fluid including no HCl, including HCl in an amount distinct from the amount of HCl in the first oilfield treatment fluid, and/or including FA1 in an amount that is the same or similar to the amount of FA1 in the first oilfield treatment fluid.
  • the first and second oilfield treatment fluids do not include both the HCl amount and the FA1 amount present in identical amounts with each other, although either one of the HCl amount or the FA1 amount may be present in identical amounts with each other. Additionally, it is contemplated that multiple stages of the first oilfield treatment fluid and/or the second oilfield treatment fluid may be performed, which stages may be equal or unequal in size or number, and/or which may include spacer fluids or not between any one or more of the stages.
  • test solutions were prepared by dissolving an amino acid into 37% HCl.
  • the 37% HCl concentration was obtained by bubbling HCl gas into the test vessel.
  • 15.8 g of L-Asparagine were dissolved into 10 mL of 37% HCl by stirring, resulting in a 1:1 molar ratio mixture of the two species.
  • test solution 0.2 mL was applied to a 25-g core of Indiana limestone at either 20° C. or 93° C. The reaction was allowed to proceed until the acid was completely spent.
  • Table 1 presents results of acid retardation tests performed with various amino acids (FA) and various amino acid:HCl molar ratios.
  • the Asparagine adduct demonstrated significantly retarded but measurable reaction rates.
  • those of Glutamine, Histidine and Glycine exhibited moderate to lower levels of retardation.
  • the adducts of Serine methyl ester, Lysine and Arginine prevented limestone dissolution (at least within the test period) at 20° C.
  • the retardation factor was too high to measure (THTM).
  • THTM* evolution of gas bubbles from the limestone surface was observed but, again, the retardation factor was too high to measure (THTM*) within the test period.
  • a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.

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US14/062,291 2013-07-31 2013-10-24 Aqueous solution and method for use thereof Active 2035-08-12 US9796490B2 (en)

Priority Applications (13)

Application Number Priority Date Filing Date Title
US14/062,291 US9796490B2 (en) 2013-10-24 2013-10-24 Aqueous solution and method for use thereof
AU2014227472A AU2014227472B2 (en) 2013-10-24 2014-09-17 Aqueous solution and method for use thereof
RU2014139259A RU2686210C2 (ru) 2013-10-24 2014-09-29 Водные растворы и способ их использования
EP14187120.2A EP2883932A3 (fr) 2013-10-24 2014-09-30 Solution aqueuse et son procédé d'utilisation
BR102014024638A BR102014024638A2 (pt) 2013-10-24 2014-10-02 composição aquosa, método para tratar uma formação em um poço subterrãneo, método para estimular uma formação em um poço subterrâneo, e método para manipular uma composição
CA2865855A CA2865855C (fr) 2013-10-24 2014-10-03 Solution aqueuse et procede d'utilisation de celle-ci
MX2016013595A MX359204B (es) 2013-10-24 2014-10-08 Solucion acuosa y metodo para su uso.
MX2014012153A MX350752B (es) 2013-10-24 2014-10-08 Solución acuosa y método para su uso.
CN201410558608.6A CN104560004B (zh) 2013-10-24 2014-10-20 水溶液及其使用方法
SA114350799A SA114350799B1 (ar) 2013-10-24 2014-10-20 محلول مائي وطريقة لاستخدامه
ARP140103989A AR098172A1 (es) 2013-10-24 2014-10-23 Solución acuosa y método para su uso
US14/824,362 US9920606B2 (en) 2013-07-31 2015-08-12 Preparation method, formulation and application of chemically retarded mineral acid for oilfield use
US15/790,928 US20180044042A1 (en) 2013-10-24 2017-10-23 Aqueous solution and method for use thereof

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US20150114647A1 (en) 2015-04-30
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EP2883932A2 (fr) 2015-06-17
BR102014024638A2 (pt) 2015-10-27
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